The present invention relates to an improved catalytic cracking process wherein the amount of sulfur compounds in the catalyst regenerator flue gas is reduced.
Catalytic cracking systems use a moving bed or a fluidized bed of particulate catalyst. The catalyst is continuously cycled between a cracking reaction zone and catalyst regeneration zone. In a fluidized cracking (FCC) system, a hydrocarbon feed stream is contacted with fluidized catalyst particles in a hydrocarbon cracking zone, or reactor, usually at a temperature of about 800.degree.-1100.degree. F. The reactions of hydrocarbons at this temperature result in deposition of carbonaceous coke on the catalyst particles. The cracked hydrocarbons are thereafter separated from the coked catalyst and withdrawn from the cracking conversion zone. The coked catalyst is then stripped of volatiles and passed to a catalyst regeneration zone. In the regenerator, the coked catalyst is contacted with a gas containing a controlled amount of molecular oxygen to burn off a desired portion of coke and simultaneously to heat the catalyst to a high temperature desired when the catalyst is again contacted with the hydrocarbon stream in the cracking zone. A flue gas is also formed by the burning procedure. After coke burnoff, the catalyst is returned to the cracking zone, where it vaporizes hydrocarbons and catalyzes hydrocarbon cracking. The flue gas is separately removed from the regenerator, and is normally passed into the atmosphere after treatment to remove particulates and carbon monoxide from it.
The product stream recovered from the reactor in a catalytic cracking unit includes a light gas fraction and a liquid hydrocarbon fraction. The term "light gas fraction", as used herein, means all components of the fluid products stream which have a normal boiling point below the boiling point of propane. The term "liquid hydrocarbon fraction", as used herein, means all C.sub.3 and higher boiling components of the fluid products stream. The yield of the liquid hydrocarbon fraction is normally represented in terms of volume percent of the hydrocarbon feed to the FCC reactor. Since the liquid hydrocarbon fraction contains substantially all the valuable components in the fluid product stream, the level of volume percent liquid product yield is one of the most important indications of the practicability of a particular FCC operation. A decline in liquid product yield of greater than one volume percent of the feed rate as a result of any change in process parameters is a sufficiently negative result that the change in parameters cannot be economically tolerated in commercial operations. Thus, any deviation from normal, optimum operation of an FCC unit that results in a decline in liquid product yield of over about one percent is impracticable.
The hydrocarbon feeds processed in commercial FCC units normally contain sulfur, herein termed "feed sulfur". It has been found that about 2-10% or more of the feed sulfur in a hydrocarbon feed stream processed in an FCC system is invariably deposited on the catalyst particles in the coke. This sulfur, herein termed "coke sulfur", is eventually cycled from the conversion zone with the coked (spent) catalyst to the regenerator. About 2-10% or more of the feed sulfur is thus continuously passed from the conversion zone into the catalyst regeneration zone with the coked catalyst.
In an FCC catalyst regenerator, coke sulfur is burned, along with the coke carbon. The primary resulting sulfur compounds are gaseous sulfur dioxide and sulfur trioxide. These are conventionally removed from the regenerator in the flue gas.
Most of the feed sulfur does not become coke sulfur in the reactor. Instead, it is converted to normally gaseous sulfur compounds, e.g., hydrogen sulfide and carbon oxysulfide, or remain as higher-boiling-range organic sulfur compounds. These fluid sulfur compounds are conventionally removed from the reactor along with the fluid hydrocarbon products. About 90% or more of the feed sulfur is continuously removed from the reactor with processed hydrocarbons, 40-60% of this being hydrogen sulfide. Means are conventionally provided for recovering hydrogen sulfide from the fluid reactor effluent. Typically, a very-low-molecular-weight off-gas stream is separated from the C.sub.3 + liquid hydrocarbons in a gas recovery unit and is treated, as by scrubbing it with an amine solution, to remove the hydrogen sulfide. Removal of sulfur compounds such as hydrogen sulfide from the fluid effluent from an FCC reactor is relatively simple and inexpensive as compared to conventional methods for removal of sulfur oxides from an FCC regenerator flue gas.
It has been suggested to reduce the amount of sulfur in FCC regenerator flue gas in commercial units, when necessary, by either: (1) desulfurizing the hydrocarbon FCC feed in a separate desulfurization unit to reduce the amount of feed sulfur prior to processing the feed in the FCC unit; or (2) desulfurizing the regenerator flue gas itself, by a conventional flue gas desulfurization procedure, after the flue gas has been removed from the FCC regenerator. Both of the foregoing alternatives require elaborate additional processing operations and necessitate substantial additional capital and utilities expenses. For this reason, the cost of processing high-sulfur feedstocks in FCC units is high. Yet, many of the petroleum stocks currently available for processing in FCC units have a high sulfur content. The inclusion of expensive extraneous equipment and procedures in refinery operations to reduce the amount of sulfur in the flue gas removed from an FCC unit is a major problem in commercial FCC processing systems.
If gaseous sulfur compounds normally removed from the unit in the flue gas can instead be removed from the reactor as hydrogen sulfide along with the processed hydrocarbons, the shifted sulfur is simply a small addition to the large amount of hydrgoen sulfide and organic sulfur already present in the reactor effluent. The small added expense, if any, of removing even as much as 5-15% more hydrogen sulfide from FCC reactor off-gas using available hydrogen sulfide removal means is substantially less than the expense incurred if separate feed desulfurization or flue gas desulfurization is instead used to reduce the amount of sulfur in the regenerator flue gas. Hydrogen sulfide recovery systems used with present commercial FCC units usually have unused capacity sufficient to remove additional hydrogen sulfide from the reactor off-gas. Existing off-gas hydrogen sulfide removal can thus handle the additional hydrogen sulfide which would be added to the off-gas if feed sulfur were substantially all removed from the FCC system in the hydrocarbon reactor effluent. It is accordingly more desirable to direct substantially all feed sulfur into the fluid products removal pathway from the reactor to reduce the amount of sulfur in the FCC regenerator flue gas, than either to desulfurize the hydrocarbon feed prior to charging it to the FCC conversion zone or to desulfurize the regenerator flue gas after it is removed from the FCC regenerator.
It has been suggested, for example in U.S. Pat. No. 3,699,037, L to reduce the amount of sulfur oxides in FCC regenerator flue gas by adding particles of Group II-A metal oxides and/or carbonates, such as dolomite, MgO or CaCO.sub.3, to the circulating catalyst in an FCC unit. The Group II-A metals react with sulfur oxides in the flue gas to form solid sulfur-containing compounds. The Group II-A metal oxides lack physical strength, and regardless of the size of particles introduced, they are rapidly reduced to fines by attrition, and rapidly pass out of the FCC unit with the catalyst fines. Thus, addition of dolomite and the like Group II-A materials must be continuous, and large amounts of the materials must be employed, in order to reduce the level of flue gas sulfur oxides for any significant period of time.
It has also been suggested, for example in U.S. Pat. No. 3,835,031, to reduce the amount of sulfur oxides in FCC regenerator flue gas by impregnating a Group II-A metal oxide onto a conventional silica-alumina cracking catalyst. The attrition problem encountered when using unsupported Group II-A metals is thereby reduced. However, it has been found that Group II-A metal oxides, such as magnesia, when used as a component of cracking catalysts, have a highly undesirable effect on the activity and selectivity of the cracking catalyst. The addition of a Group II-A metal to a cracking catalyst results in two particularly noticeable adverse consequences relative to the results obtained without the Group II-A metals: (1) the yield of the liquid hydrocarbon fraction is substantially reduced, typically by greater than one volume percent of the feed volume; and (2) the octane rating of the gasoline or naphtha fraction (75.degree.-430.degree. F. boiling range) is substantially reduced. Both of the above adverse consequences are severely detrimental to the economic viability of an FCC operation, and even complete removal of sulfur oxides from regenerator flue gas could not compensate for the losses in yield and octane which result from adding Group II-A metals to an FCC catalyst.
Alumina has been a component of many FCC and other cracking catalysts, but primarily in intimate chemical combination with silica. Alumina itself has low acidity and is generally considered to be undesirable for use as a cracking catalyst. The art has taught that alumina is nonselective, i.e., the cracked hydrocarbon products recovered from an FCC or other cracking unit using an alumina catalyst would not be the desired valuable products, but would include, for example, relatively large amounts of C.sub.2 and lighter hydrocarbon gases. Intimate combinations of alumina with silica, e.g., as cogels, clays, zeolites, etc., have been found to be high in acidity, and are excellent cracking catalysts. They are used in most, if not all, commercial FCC units.
Copending application Ser. No. 666,115 (now U.S. Pat. No. 4,071,456) discloses that alumina can be circulated in an FCC system in order to shift sulfur from the regenerator flue gas to the reactor effluent. The alumina can be used either as a component of the catalyst particles or in the form of separate particles physically mixed with the catalyst particles.
Copending application Ser. No. 751,640 (now U.S. Pat. No. 4,115,249) discloses that sulfur can be shifted from the regenerator flue gas to the reactor effluent in an FCC system by circulating in the system a silica-containing catalyst which has been calcined and then impregnated with alumina or a compound decomposable to alumina.
Virtually all FCC catalysts presently used include a gel or clay type silica-alumina matrix in which are dispersed particles of a zeolitic crystalline aluminosilicate. One method used commercially for manufacturing the catalysts used in FCC systems involves formation of a silica-alumina cogel, addition of small particles of a zeolite to the cogel, and formation of catalyst particles by spray-drying. Another commercial method for manufacturing FCC catalyst involves formation of zeolite particles in situ in a silica-alumina mixture such as a clay, by heat, pressure, acid treatment, etc., followed by spray-drying particle formation.
Several U.S. patents describe the incorporation of fine particles of an inorganic oxide into catalyst particles. U.S. Pat. No. 2,487,065 discloses dispersing a fine powder of fused alumina, clay, pumice or the like into an inorganic acid sol, setting the sol into a hydrogel, and drying particles of the hydrogel to form a catalyst or catalyst base. U.S. Pat. No. 2,727,868 describes thermal treatment of kaolin clay, followed by mixing the clay with a silica gel. U.S. Pat. No. 2,935,463 describes physical mixtures of alumina into clays and synthetic silica-alumina mixtures. U.S. Pat. No. 3,193,511 describes dispersing into a silica-alumina matrix 2- to 7- micron-diameter particles of alpha-alumina which has been calcined at above 2000.degree. F. U.S. Pat. No. 3,224,961 shows physical mixture or precipitation of alumina into silica-alumina particles. U.S. Pat. No. 3,312,615 describes physical mixture of molecular sieve particles and alpha-alumina particles into a silica-alumina matrix. U.S. Pat. No. 3,542,670 describes formation of a physical mixture of hydrated alumina and zeolite particles with a silica-alumina hydrogel. U.S. Pat. No. 3,788,977 describes the addition of molecular sieve particles and alumina particles to a clay or synthetic silica-alumina matrix. The alumina used has previously been impregnated with platinum or uranium. U.S. Pat. No. 3,933,621 describes the manufacture of an FCC catalyst containing 56-90 weight percent alumina. U.S. Pat. No. 4,012,339 describes the use of calcined alumina fines in the preparation of an extruded catalyst.